To form a wellbore or borehole in a formation, a drilling assembly (also referred to as the “bottom hole assembly” or the “BHA”) carrying a drill bit at its bottom end is conveyed downhole. The wellbore may be used to store fluids in the formation or obtain fluids, such as hydrocarbons, from one or more production zones in the formation. Several techniques may be employed to stimulate hydrocarbon production. For example, a plurality of wellbores (also “boreholes” or “wells”), such as a first and second wellbore, may be formed in a formation. The first wellbore is an injection wellbore and the second wellbore is a production wellbore. A flow of pressurized fluids from the first wellbore cause flow of formation fluids to the production wellbore. Specifically, the fluid is flowed downhole within a tubular disposed in the first or injection wellbore. One or more flow control apparatus, such as a valve, is located in the tubular to control the pressurized fluid flow into the formation. The pressurized fluid then causes an increased pressure within the formation resulting in flow of formation fluid into a producing string located in the second wellbore. A surface fluid source, such as a pump, provides the pressurized injection fluid to each flow control apparatus downhole.
If the fluid source shuts down or malfunctions, a pressure differential occurs between the formation zone receiving the injected fluid and the fluid inside the tubular. Specifically, a pressure caused by injecting fluid into a zone of the formation is significantly higher than the hydrostatic pressure within the tubular. The pressure differential can cause crossflow from the high pressure zone to other lower pressure zones in the formation. The flow from the high pressure zone can cause flow of sand and debris into the tubular and lower pressure zones, inhibiting flow paths and causing damage to the tubular string. Further, flow of sand and fluids from a first zone to a second zone eliminates isolation of zones, which is desirable during production. In addition flow of fluid from a high pressure zone can cause a high pressure wave or water hammer to propagate uphole in the tubular. The high pressure wave can damage equipment within the tubular string and at the surface.
One type of flow control device is controlled from the surface. A control signal to close fluid flow in the device may take several minutes or more to communicate from the surface. Due to the delayed control signal, the device remains open after a pump shut down, leading to communication of the pressure differential (between the formation and tubular) and resulting cross flow and pressure wave. In addition, in cases where the fluid source is shut down frequently, the flow control device is also closed frequently. The repeated opening and closing of the device increases the chance of failure, such as seal wear out. Another type of flow control device is controlled through intervention method (such as wire-line and coil tubing operations). In those examples, the delay to close flow devices is longer (e.g., 1-3 days), wherein the device remains open after a pump shut down, leading to communication of the pressure differential (between the formation and tubular) and resulting cross flow and pressure wave.